Well configurations for limited reflux

ABSTRACT

Methods and systems produce petroleum products by steam assisted gravity drainage with dual producers separated vertically and laterally from at least one injector. Placement of the producers limits temperature rise of draining fluids and hence reflux of non-condensable gases injected with steam. In particular, the fluids drain along a steam chamber boundary for recovery at positions that are not in a direct downward path from where the injector is introducing heat.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefit under 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/679,248 filed Aug. 3, 2012, entitled “WELL CONFIGURATIONS FOR LIMITED REFLUX,” which is incorporated herein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

None.

FIELD OF THE INVENTION

Embodiments of the invention relate to producing hydrocarbons by steam assisted gravity drainage with dual producers separated vertically and laterally from at least one injector.

BACKGROUND OF THE INVENTION

Bitumen recovery from oil sands presents technical and economic challenges due to high viscosity of the bitumen at reservoir conditions. Steam assisted gravity drainage (SAGD) provides one process for producing the bitumen from a reservoir. During SAGD operations, steam introduced into the reservoir through a horizontal injector well transfers heat upon condensation and develops a steam chamber in the reservoir. The bitumen with reduced viscosity due to this heating drains together with steam condensate along a boundary of the steam chamber and is recovered via a producer well placed parallel and beneath the injector well.

However, costs associated with energy requirements for the SAGD operations limit economic returns. Accumulation in the reservoir of gaseous carbon dioxide (CO2) and/or solvent that may be injected with the steam in some applications can further present problems. For example, the gaseous CO2/solvent acts as a thermal insulator impairing heat transfer from the steam to the bitumen, decreases temperature of the drainage interface due to partial pressure impact, and decreases effective permeability to oil as a result of increased gas saturation.

Therefore, a need exists for methods and systems for recovering hydrocarbons from oil sands with an efficient steam-to-oil ratio.

BRIEF SUMMARY OF THE DISCLOSURE

In one embodiment, a method of recovering hydrocarbons includes introducing a gaseous mixture including steam and non-condensible gas (NCG) into an injection well. The mixture passes into a formation through a horizontal length of the injection well. The method further includes recovering a petroleum fluid from first and second production wells spaced laterally from one another by at least 10 meters and oriented horizontal and parallel to the horizontal length of the injection well that is disposed in vertical alignment 1 to 10 meters above a midpoint between the production wells.

According to one embodiment, a method of recovering hydrocarbons includes introducing a gaseous mixture including steam and NCG into an injection well having a horizontal length through which the mixture passes into a formation. In addition, a steam chamber generates within the formation along with drainage pathways at a boundary of the chamber that end at first and second production wells and remain below a threshold temperature for retaining the NCG in solution due to location of the production wells below and on each side of the injection well. The method also includes recovering a petroleum fluid from the production wells that are oriented horizontal and parallel to the horizontal length of the injection well.

For one embodiment, a system for recovering hydrocarbons includes an injection well disposed in a formation and in fluid communication with a gaseous mixture of steam and NCG. The injection well includes a horizontal length thereof through which the mixture is passable into the formation. The system further includes first and second production wells spaced laterally from one another by at least 10 meters and oriented horizontal and parallel to the horizontal length of the injection well that is disposed in vertical alignment 1 to 10 meters above a midpoint between the production wells through which a petroleum fluid is recoverable.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present invention and benefits thereof may be acquired by referring to the follow description taken in conjunction with the accompanying drawings.

FIG. 1 is a schematic of an injector with dual producers in a steam assisted gravity drainage operation, according to one embodiment of the invention.

FIG. 2 is a schematic of dual injectors with dual producers in a steam assisted gravity drainage operation, according to one embodiment of the invention.

FIG. 3 is a graph of oil production rate versus time for comparison of simulated results based on well configurations such as shown in FIG. 1, according to one embodiment of the invention.

FIG. 4 is a graph of cumulative steam to oil ratio versus time for comparison of simulated results based on well configurations such as shown in FIG. 1, according to one embodiment of the invention.

FIG. 5 is a graph of oil production rate versus time for comparison of simulated results based on well configurations such as shown in FIG. 2, according to one embodiment of the invention.

FIG. 6 is a graph of cumulative steam to oil ratio versus time for comparison of simulated results based on well configurations such as shown in FIG. 2, according to one embodiment of the invention.

DETAILED DESCRIPTION

Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.

For some embodiments, methods and systems produce petroleum products by steam assisted gravity drainage (SAGD) with dual producers separated vertically and laterally from at least one injector. Placement of the producers limits temperature rise of draining fluids and hence reflux of non-condensable gases (NCG) injected with steam. In particular, the fluids drain along a steam chamber boundary for recovery at positions that are not in a direct downward path from where the injector is introducing heat into the formation.

The NCG refers to a chemical that remains in the gaseous phase under process conditions within the formation. Examples of the NCG include, but are not limited to, air, carbon dioxide (CO₂), nitrogen (N₂), carbon monoxide (CO), hydrogen sulfide (H₂S), hydrogen (H₂), anhydrous ammonia (NH₃) and flue gas. Flue gas or combustion gas refers to an exhaust gas from a combustion process that may otherwise exit to the atmosphere via a pipe or channel. Flue gas often comprises nitrogen, CO₂, water vapor, oxygen, CO, nitrogen oxides (NO_(x)) and sulfur oxides (SO_(x)). The NCG can make up from 1 to 40 volume percent of a mixture that is injected into the formation.

As used herein, hydrocarbon solvent refers to a chemical consisting of carbon and hydrogen atoms which dissolves into products being recovered to increase fluidity and/or decrease viscosity of the products. The hydrocarbon solvent can have, for example, 1 to 12 carbon atoms (C₁-C₁₂) or 1 to 4 carbon atoms (C₁-C₄) per molecule. The C₁ to C₄ hydrocarbon solvent may include methane, ethane, propane and/or butane. The hydrocarbon solvent can be introduced into the formation as a gas or as a liquid. Under the pressures of the formation, the hydrocarbon solvent may be another example of the NCG or may condense from a gas to a liquid, especially if the hydrocarbon solvent has 2 or more carbon atoms.

Given high energy costs of SAGD, steam co-injection with carbon dioxide and/or hydrocarbon solvents provides one option in some embodiments for reducing the energy used by reducing heat losses and facilitating viscosity reduction. The NCG, for example, may accumulate in an upper part of the steam chamber where the NCG acts as insulation for reducing heat loss to overburden. However, too much accumulation of the NCG may suppress production.

For example, the NCG at a side boundary of the steam chamber may act as a thermal insulating blanket that impairs transport of heat from the steam to the bitumen. Due to the partial pressure effect, the temperature of the drainage interface decreases and the bitumen that drains along the boundary also becomes less mobile. Gas saturation increases as a direct result of NCG accumulation at the drainage interface such that the effective permeability to oil decreases.

Some of the NCG that accumulates in the steam chamber comes from refluxing of the NCG dissolved in the draining fluids prior to recovery. The NCG liberates from the fluid in liquid phase back into gaseous phase that then moves upward into the steam chamber. Solubility of the NCG in the draining fluids depends on temperature. For example, minimal carbon dioxide dissolves in bitumen at steam chamber temperatures above 200° C. but will dissolve in the bitumen at lower temperatures along a boundary of the steam chamber.

Increase in temperature of the draining fluid due to heat transfer near the injector depends on proximity of the draining fluid passing by the injector. As described herein for some embodiments, drainage pathways at a boundary of the steam chamber that end at the production wells remain below a threshold temperature for retaining the NCG in solution. Prior well configurations and operations by contrast provided undesired temperature profiles in the formation causing effervescence of the NCG from the bitumen, resulting in the reflux of the NCG into the steam chamber.

Since direct steam generator products have the NCG (e.g., 10 to 12 weight percent carbon dioxide) intermixed with steam, direct steam generation when used to supply a SAGD process according to some embodiments may reduce the steam-oil ratio and improve economic recovery. The direct steam generation also consumes less water compared to conventional steam generation. However, the NCG from the direct steam generator products may accumulate in the steam chamber to a level more than desired without utilizing approaches described herein.

The direct steam generation refers to making steam by direct contact of water with combustion and hot combustion products. Typically, direct steam generators include a combustion zone, a plurality of mixing zones downstream from the combustion zone, and an exhaust barrel downstream from the mixing zones. As an example, a direct steam generator such as that described in U.S. Pat. No. 6,206,684 (assigned to Clean Energy Systems and incorporated herein by reference in its entirety) can be used or modified for some embodiments.

FIG. 1 shows an injection well 100 disposed above a first production well 102 and a second production well 103 within a formation. While viewed transverse to a horizontal length, the wells 100, 102, 103 include horizontal sections that traverse through the formation containing petroleum products, such as heavy oil or bitumen. In operation, a steam chamber 104 develops as a mixture of steam and NCG is introduced into the formation through the injection well 100 and a resulting petroleum fluid is recovered from the production wells 102, 103. Use of the productions wells 102, 103 for this recovery may begin upon initial development of the steam chamber 104.

The steam and the NCG contacts the bitumen, condenses and/or dissolves in the bitumen if soluble. Heat transfer upon condensation and solvent based viscosity reduction makes the bitumen mobile and enables gravity drainage thereof. The petroleum fluid of steam condensate, the bitumen and any dissolved NCG migrates through the formation due to gravity and is gathered at each of the production wells 102, 103 for recovery to surface.

In some embodiments, a distance of at least 10 meters separates the first production well 102 from the second production well 103, which are spaced laterally from one another and oriented horizontal and parallel to a horizontal length of the injection well 100. Lateral spacing of the production wells 102, 103 promotes lateral development of the steam chamber 104. In some embodiments, the steam chamber 104 generation occurs without recovery of the petroleum fluid in an area of the formation having vertical alignment with the injection well 100. The injection well 100 for some embodiments aligns in a vertical direction 1 to 10 meters above a midpoint between the production wells 102, 103.

In some embodiments, spacing between the first and second production wells 102, 103 ranges from 10 to 20 meters. With such spacing, the first and second production wells 102, 103 rely only on fluid communication being established during startup with the injection well 100. Any additional adjacent injection wells associated with corresponding production wells may be too far off for effective fluid communication at startup without creating such a tight spacing of all wells to be uneconomical. Multilaterals may form the first and second production wells 102, 103, which thus connect to a vertical common wellbore instead of separate independent wellbores for each of the production wells 102, 103. The productions wells 102, 103 may extend along a bottom of a hydrocarbon reservoir in the formation and may be disposed in a common horizontal plane.

This operation and configuration of the wells 100, 102, 103 provides a desired temperature profile in the formation and limits reflux and accumulation of the NCG, such as the carbon dioxide. Drainage pathways at a boundary of the steam chamber 104 terminate at the production wells 102, 103 and remain below a threshold temperature for retaining the NCG in solution. Limiting the accumulation of the NCG promotes growth of the steam chamber 104, which also develops with a desired shape by employing approaches described herein.

FIG. 2 illustrates an injection well 200 disposed below an auxiliary well 201 and above a first production well 202 and a second production well 203 within a formation. The auxiliary well 201 supplements the injection well 200 in introducing a mixture of steam and NCG into the formation and may further facilitate creation of a desired temperature profile within the formation. The injection well 200 and production wells 202, 203 otherwise correspond in function and design as like elements described herein with respect to FIG. 1.

In some embodiments, the auxiliary well 201 aligns in a vertical direction at least 5 meters, or between 10 and 20 meters, above a horizontal length of the injection well 200. The auxiliary well extends parallel with the horizontal length of the injection well 200. For example, the injection well 200 may pass through the formation 5 meters above a horizontal plane of the production wells 202, 203 with the auxiliary well 201 disposed 5 meters above the injection well 200.

In operation, the mixture of the steam and NCG may pass through both the injection well 200 and the auxiliary well 201 simultaneously. An alternative staged strategy shuts in the injection well 200 stopping introduction of the mixture via the injection well 200 before injecting the mixture into the auxiliary well 201. Shutting in the injection well 200 may occur once thermal communication is established between the auxiliary well 201 and the production wells 202, 203 (e.g., after about 2 years).

FIG. 3 shows simulated results for oil production rate versus time with a first curve 301 corresponding to a conventional steam only vertical aligned SAGD well pair, a second curve 302 corresponding to a well configuration as depicted in FIG. 1 and operating with a direct steam generator, and a third curve 303 corresponding to the SAGD well pair operating with the direct steam generator. The oil production rate thus improves with the well configuration as depicted in FIG. 1. In particular, the second curve 302 remains about the third curve 303 throughout most of the time and is above the first curve 301 as the time progresses.

FIG. 4 illustrates simulated results for cumulative steam to oil ratio versus time with a first curve 401 corresponding to a conventional steam only vertical aligned SAGD well pair, a second curve 402 corresponding to a well configuration as depicted in FIG. 1 and operating with a direct steam generator, and a third curve 403 corresponding to the SAGD well pair operating with the direct steam generator. The second curve 402 remains below the first and third curves 401, 403 most of the time. Accordingly, embodiments described herein retain superior energy efficiency obtained by use of the direct steam generator as evidenced by a more than 20% reduction in the cumulative steam to oil ratio compared to steam only SAGD.

FIG. 5 shows simulated results for oil production rate versus time with a first curve 501 corresponding to a conventional steam only vertical aligned SAGD well pair, a second curve 502 corresponding to a well configuration as depicted in FIG. 2 and operating with a direct steam generator, and a third curve 503 corresponding to the SAGD well pair operating with the direct steam generator. The oil production rate thus improves with the well configuration as depicted in FIG. 2. Like FIG. 3, the second curve 502 remains about the third curve 503 throughout most of the time and is above the first curve 501 as the time progresses.

FIG. 6 illustrates simulated results for cumulative steam to oil ratio versus time with a first curve 601 corresponding to a conventional steam only vertical aligned SAGD well pair, a second curve 602 corresponding to a well configuration as depicted in FIG. 2 and operating with a direct steam generator, and a third curve 603 corresponding to the SAGD well pair operating with the direct steam generator. Similar to FIG. 4, the second curve 602 remains below the first and third curves 601, 603 most of the time. Accordingly, embodiments described herein retain superior energy efficiency obtained by use of the direct steam generator as evidenced by a more than 20% reduction in the cumulative steam to oil ratio compared to steam only SAGD.

In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as an additional embodiment of the present invention.

Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims, while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents. 

1. A method of recovering hydrocarbons, comprising: introducing a gaseous mixture including steam and non-condensable gas (NCG) into an injection well having a horizontal length through which the mixture passes into a formation; and recovering a petroleum fluid from first and second production wells spaced laterally from one another by 10 to 20 meters and oriented horizontal and parallel to the horizontal length of the injection well that is disposed in vertical alignment 1 to 10 meters above a midpoint between the production wells.
 2. The method according to claim 1, further comprising generating a steam chamber within the formation and drainage pathways at a boundary of the chamber that end at the production wells and remain below a threshold temperature for retaining the NCG in solution.
 3. The method according to claim 1, wherein the NCG includes at least one of nitrogen, air, carbon dioxide, flue gas, hydrogen sulfide, hydrogen, anhydrous ammonia.
 4. The method according to claim 1, further comprising creating the mixture with a direct steam generator.
 5. The method according to claim 1, wherein the NCG includes a hydrocarbon solvent.
 6. The method according to claim 1, wherein the NCG includes a hydrocarbon solvent with between one and four carbon atoms per molecule.
 7. The method according to claim 1, further comprising introducing the mixture into an auxiliary well disposed in vertical alignment and above the injection well.
 8. The method according to claim 1, further comprising injecting the mixture into an auxiliary well above the horizontal length of the injection well after stopping introduction of the mixture into the injection well.
 9. The method according to claim 1, wherein the first and second production wells are multilaterals from a common wellbore.
 10. The method according to claim 1, wherein the production wells are used upon initial development of a steam chamber above the injection well.
 11. A method of recovering hydrocarbons, comprising: introducing a gaseous mixture including steam and non-condensable gas (NCG) into an injection well having a horizontal length through which the mixture passes into a formation; generating a steam chamber within the formation and drainage pathways at a boundary of the chamber that end at first and second production wells and remain below a threshold temperature for retaining the NCG in solution due to location of the production wells below and on each side of the injection well; and recovering a petroleum fluid from the production wells that spaced apart by 10 to 20 meters and are oriented horizontal and parallel to the horizontal length of the injection well.
 12. The method according to claim 11, further comprising introducing the mixture into an auxiliary well disposed in vertical alignment and above the injection well.
 13. The method according to claim 11, wherein the steam chamber is generated without recovery in an area of the formation having vertical alignment with the injection well.
 14. The method according to claim 11, wherein the NCG includes carbon dioxide.
 15. A system for recovering hydrocarbons, comprising: an injection well disposed in a formation and in fluid communication with a gaseous mixture of steam and non-condensable gas (NCG), wherein the injection well has a horizontal length through which the mixture is passable into the formation; and first and second production wells spaced laterally from one another by 10 to 20 meters and oriented horizontal and parallel to the horizontal length of the injection well that is disposed in vertical alignment 1 to 10 meters above a midpoint between the production wells through which a petroleum fluid is recoverable.
 16. The system according to claim 15, wherein the gaseous mixture is a direct steam generator product.
 17. The system according to claim 15, further comprising an auxiliary well disposed in vertical alignment above the injection well and through which the mixture is passable into the formation. 